Determining the fluid placement of injected fluid in a well is a long standing challenge in the oilfield and other well-related industries. When a fluid is injected into a well, it is the intention for that fluid to flow into a target region such as a particular rock formation. However, there are numerous challenges to both placement and determination of the placement of the injected fluid.
For example, the fluid may communicate with formations outside the target region by flowing behind an imperfect cement sheath around a borehole casing or by creating a fracture, which may grow through a formation, causing fluid to flow into an undesired zone. Allowing fluid into regions outside the target region is undesirable for several reasons. First, the fluid that enters zones outside the target region does not support the injection goals and is wasted. Second, fluid injected into regions outside the target region may cause communication with other zones in a well and cause a detriment to production of the target region. Finally, fluid injected into regions outside the target region may violate a duty owed by the operator either under contract, environmental, and/or other laws.
Several methods of determining injected fluid vertical placement within a borehole are known in the art. Two common methods are radioactive logging and temperature logging. Neither of these two methods can be performed in real-time while fluid is being injected, rather both determination methods require a tool to be run down the bore after the injection work is completed. Further, neither of these methods can detect borehole deviation from the fracture plane, and therefore both methods may significantly underestimate the true height of the fracture without providing any feedback that deviation has occurred. Also, radioactive logging requires the handling of radioactive tracers, and the associated environmental, regulatory and handling issues.
Other methods of determining fluid placement include tiltmeter surveys and microseismic mapping. These techniques can be utilized during a fluid injection event. However, these techniques have important limitations. They require use of a nearby offset well that must be shut down during the testing. Not every well has a nearby offset, and production shutdowns are almost always undesirable. Further, the tiltmeter survey measures small deviations in the offset well due to rock stresses, and is best for fracture treatments and not other types of injection that may not induce a fracture or significant stresses in the injected formation. Microseismic mapping requires microseismic events to detect fracture height. In boundary layers that may experience low fluid leakoff, the microseismic events may be too small to measure, and may cause the microseismic mapping to determine the fracture height inaccurately
One method of estimating fracture height is a fluid efficiency test in which a pre-fracture injection is performed, and a fiber optic cable disposed within the borehole checks the temperature versus a depth profile. The fluid placement during the pre-fracture pumping is used to estimate the fracture height. However, this method can only detect the fracture height created during the test itself, which generally uses much smaller fluid volume than an actual fracture treatment resulting in significantly smaller fracture height. The proppant and other additives used during the fracture treatment introduce additional hydrostatic head and friction at the perforating holes that change the stresses on the formation and the cement sheath behind the casing. None of these effects can be modeled well for the fluid efficiency test. Further, the fluid efficiency test method does not detect borehole deviation from the fracture plane and can therefore significantly underestimate the true height of the fracture without providing feedback that a borehole-fracture deviation has occurred. This method also introduces additional fluid into a formation and thus introduces extra cost and time, and causes permeability damage to the formation. Finally, the fluid efficiency test cannot determine the actual height of the fracture as the fracture treatment occurs, or report a real time response to height growth.
It is evident that a need exists for an apparatus, system, and method for determining the vertical placement into a formation of a fluid injected into a borehole. Such an apparatus, system, and method would not require the use of an offset well, would provide vertical placement information in real-time while the fluid is injected, and would not introduce any extra fluid into formation.
It would also be desirable that such an apparatus, system, and method provide an indicator that a borehole to fracture plan deviation has occurred, and that the vertical placement indication may not be reliable because of the deviation. Accordingly, the present invention has been developed to provide such an apparatus, system, and method for determining the vertical placement of injected fluid into a formation that overcome many or all of the shortcomings in the conventional methods.